Hydraulic fracturing fluid

ABSTRACT

A fracturing fluid including a base fluid including salt water, a polymer, a crosslinker, and a nanomaterial. The crosslinker may include a Zr crosslinker, a Ti crosslinker, an Al crosslinker, a borate crosslinker, or a combination thereof. The nanomaterial may include ZrO 2  nanoparticles, TiO 2  nanoparticles, CeO 2  nanoparticles; Zr nanoparticles, Ti nanoparticles, Ce nanoparticles, metal-organic polyhedra including Zr, Ti, Ce, or a combination thereof; carbon nanotubes, carbon nanorods, nano graphene, nano graphene oxide; or any combination thereof. The viscosity and viscosity lifetime of fracturing fluids with both crosslinkers and nanomaterials are greater than the sum of the effects of crosslinkers and nanomaterials taken separately. Moreover, this synergistic effect offers significant, practical advantages, including the ability to use salt water rather than fresh water for fracturing fluids, the ability to reduce polymer loading to achieve a desired viscosity, and the ability to achieve better formation cleanup after the fracturing treatment.

TECHNICAL FIELD

This disclosure relates to high temperature salt water-based fracturingfluids enhanced with nanomaterials.

BACKGROUND

Fracturing fluid is often injected into subterranean reservoirs tohydraulically fracture the reservoir rock. Fracturing fluid is commonlyformulated with fresh water. However, fresh water can be costly anddifficult to obtain in some production areas. Use of seawater, producedwater, brine, or the like with high levels of total dissolved solids(TDS) as a base fluid for hydraulic fracturing can be limited by theinstability of the resulting fracturing fluids at elevated temperatures.

SUMMARY

In a first general aspect, a fracturing fluid includes a base fluidincluding salt water, a polymer, a crosslinker, and a nanomaterial.

Implementations of the first general aspect may include one or more ofthe following features.

The base fluid may include total dissolved solids of at least about 500mg/L. The salt water may include seawater, produced water, brine,brackish water, or a combination thereof. In some cases, the seawaterincludes untreated seawater.

The crosslinker may include a Zr crosslinker, a Ti crosslinker, an Alcrosslinker, a borate crosslinker, or a combination thereof. In somecases, the fracturing fluid includes from about 0.02% to about 2% byweight of the crosslinker.

The nanomaterial may include ZrO₂ nanoparticles, TiO₂ nanoparticles,CeO₂ nanoparticles; Zr nanoparticles, Ti nanoparticles, Cenanoparticles, metal-organic polyhedra comprising Zr, Ti, Ce, or acombination thereof; carbon nanotubes, carbon nanorods, nano graphene,nano graphene oxide; or any combination thereof. In some cases, thenanomaterial is stabilized with a polymer, a surfactant, or acombination thereof. In one example, the nanomaterial is stabilized withpolyvinylpyrrolidone. The fracturing fluid may include about 0.0002% toabout 2% by weight of the nanomaterial.

The polymer may include guar, hydroxpropyl guar, carboxymethylhydroxypropyl guar, or a combination thereof.

The fracturing fluid may include one or more additives, such as abactericide, a buffer, a stabilizer, a viscosity breaker, a surfactant,a scale inhibitor, or a combination thereof. In one example, the bufferincludes bicarbonate, carbonate, acetate, or a combination thereof. Thestabilizer may include sodium thiosulfate, sorbitol, alkylated sorbitol,or a combination thereof. The viscosity breaker may include an oxidativebreaker.

As described herein, the viscosity and viscosity lifetime of fracturingfluids with both crosslinkers and nanomaterials are greater than the sumof the effects of crosslinkers and nanomaterials taken separately.Moreover, this synergistic effect offers significant, practicaladvantages, including the ability to use salt water rather than freshwater for fracturing fluids, the ability to reduce polymer loading toachieve a desired viscosity, and the ability to achieve better formationcleanup after the fracturing treatment.

The details of one or more implementations of the subject matterdescribed in this specification are set forth in the accompanyingdrawings and the description below. Other features, aspects, andadvantages of the subject matter will become apparent from thedescription, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts delivery of a fracturing fluid to a subterraneanformation.

FIG. 2 shows plots of viscosity vs. time for the fracturing fluids ofExample 1.

FIG. 3 shows plots of viscosity vs. time for the fracturing fluids ofExample 2.

FIG. 4 shows plots of viscosity vs. time for the fracturing fluids ofExample 3.

FIG. 5 shows plots of viscosity vs. time for the fracturing fluids ofExample 4.

FIG. 6 shows plots of viscosity vs. time for the fracturing fluids ofExample 5.

FIG. 7 shows plots of viscosity vs. time for the fracturing fluids ofExample 6.

DETAILED DESCRIPTION

FIG. 1 depicts an example well system 100 for applying a fracturetreatment to a subterranean formation 101. Fracture treatments can beused, for example, to form or propagate fractures in a rock layer byinjecting pressurized fluid. The fracture treatment can include an acidtreatment to enhance or otherwise influence production of petroleum,natural gas, coal seam gas, or other types of reservoir resources. Theexample well system 100 includes an injection system 110 that appliesfracturing fluid 108 to a reservoir 106 in the subterranean zone 101.The subterranean zone 101 can include a formation, multiple formationsor portions of a formation. The injection system 110 includes controltrucks 112, pump trucks 114, a wellbore 103, a working string 104 andother equipment. In the example shown in FIG. 1, the pump trucks 114,the control trucks 112 and other related equipment are above the surface102, and the wellbore 103, the working string 104, and other equipmentare beneath the surface 102. An injection system can be configured asshown in FIG. 1 or in a different manner and it can include additionalor different features as appropriate. The injection system 110 can bedeployed in any suitable environment, for example, via skid equipment, amarine vessel, sub-sea deployed equipment, or other types of equipment.

The wellbore 103 shown in FIG. 1 includes vertical and horizontalsections. Generally, a wellbore can include horizontal, vertical, slant,curved, and other types of wellbore geometries and orientations, and theacid treatment can generally be applied to any portion of a subterraneanzone 101. The wellbore 103 can include a casing that is cemented orotherwise secured to the wellbore wall. The wellbore 103 can be uncasedor include uncased sections. Perforations can be formed in the casing toallow fracturing fluids and/or other materials to flow into thereservoir 106. Perforations can be formed using shape charges, aperforating gun, and/or other tools.

The pump trucks 114 can include mobile vehicles, immobile installations,skids, hoses, tubes, fluid tanks or reservoirs, pumps, valves, and/orother suitable structures and equipment. The pump trucks 114 cancommunicate with the control trucks 112, for example, by a communicationlink 113. The pump trucks 114 are coupled to the working string 104 tocommunicate the fracturing fluid 108 into the wellbore 103. The workingstring 104 can include coiled tubing, sectioned pipe, and/or otherstructures that communicate fluid through the wellbore 103. The workingstring 104 can include flow control devices, bypass valves, ports, andor other tools or well devices that control the flow of fracturing fluidfrom the interior of the working string 104 into the reservoir 106.

Fracturing fluid 108 includes a base fluid and one or more polymers,crosslinkers, and nanomaterials. Fracturing fluid 108 may also includeone or more buffers, stabilizers, and viscosity breakers. In some cases,fracturing fluid 108 include one or more other additives.

Base fluid in fracturing fluid 108 includes salt water. As describeherein, “salt water” generally refers to water including dissolved saltssuch as sodium chloride, such as seawater (e.g., untreated seawater),produced water, brine, brackish water, and the like. The base fluid istypically high in total dissolved solids (TDS). TDS in the base fluidmay be in a range from about 500 mg/L to over 300,000 mg/L. An acidic pHadjusting agent such as acetic acid or diluted hydrogen chloride (HCl)may be used to adjust the pH of the base fluid to a pH of less thanabout 7, more particularly, to a pH of less than about 6.

Polymers suitable for fracturing fluid 108 include polysaccharides suchas hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG),guar, carboxymethyl guar (CMG), hydrophobically modified guars,guar-containing compounds, and artificially modified polymers, and otherpolymers generally known in the art to be suitable for fracturingfluids. The polymer may be in the form of a slurry. Slurries can be madeby dispersions of dry polymer particles in solvent like mineral oil witha suspending aid such as modified clay. Fracturing fluid 108 typicallyincludes about 5 pounds per thousand gallons of fracturing fluid (ppt)to about 100 ppt of one or more such polymers.

Crosslinkers suitable for fracturing fluid 108 include zirconium (Zr)crosslinkers, typically having a ZrO₂ content of about 4 wt % to about14 wt % or more. Fracturing fluid 108 typically includes about 0.1gallons per thousand gallons of fracturing fluid (gpt) to about 10 gptof one or more such crosslinkers. Suitable zirconium crosslinkersinclude by non-limiting example, zirconium lactates (such as sodiumzirconium lactate), triethanolamines, 2,2′-iminodiethanol, and withmixtures of these ligands. Crosslinkers suitable for fracturing fluidmay also include titanium (Ti) crosslinkers. Suitable titanatecrosslinkers include by non-limiting example, titanate crosslinkers withligands such as lactates and triethanolamines, and mixtures, andoptionally delayed with hydroxyacetic acid. Crosslinkers suitable forfracturing fluid may also include borate crosslinkers, aluminum (Al)crosslinkers, chromium (Cr) crosslinkers, iron (Fe) crosslinkers,hafnium (Hf) crosslinkers, and combinations thereof.

Buffers suitable for fracturing fluid 108 include bicarbonate (such asNaHCO₃), carbonate (such as Na₂CO₃), phosphate, hydroxide, acetate,formate, and combinations thereof.

Stabilizers suitable for fracturing fluid 108 include sodium thiosulfate(Na₂S₂O₃ or Na₂S₂O₃.5H₂O), sorbitol and commercially available alkylatedsorbitol.

Nanomaterials suitable for fracturing fluid 108 include ZrO₂, TiO₂, andCeO₂ nanoparticles; polyvinylpyrrolidone (PVP)-stabilized ZrO₂, TiO₂,and CeO₂ nanoparticles, carbon nanomaterials (carbon nanorods, carbonnanotubes, carbon nanodots, nano graphene, nano graphene oxide, and thelike); Zr, Ti, and Ce nanoparticles and other metal nanoparticles;metal-organic polyhedra including Zr, Ti, or Ce, and other metals. Asused herein, “metal-organic polyhedra” refer to a hybrid class ofsolid-state crystalline materials constructed from the in-situ assemblyof highly modular pre-designed molecular building blocks (MBBs) intodiscrete architectures (0-D) containing a cluster of multi-valent metalnodes. Suitable nanomaterials may have a dimension in a range betweenabout 0.1 nm and about 1000 nm. The nanomaterials may be added assolutions in which the nanoparticles are suspended and stabilized withsurfactants and/or polymers like polyvinylpyrrolidone. Fracturing fluid108 typically includes about 0.0002% to 2% by weight of fluid of one ormore such nanomaterials. In some cases, the nanomaterials and thecrosslinkers include a common metal (e.g., Zr or Ti).

Viscosity breakers suitable for fracturing fluid 108 include oxidativebreakers such as persulfate (e.g., sodium persulfate), bromate (e.g.,sodium bromate). Fracturing fluid 108 typically includes one or moresuch viscosity breakers and related encapsulated breakers.

Additives suitable for fracturing fluid 108 also include surfactants,scale inhibitors, clay stabilizers, and the like, depending on thespecific requirements of oilfield operations. A surfactant present infracturing fluid 108 acts as a surface active agent and may function asan emulsifier, dispersant, oil-wetter, water-wetter, foamer, anddefoamer. Suitable examples of surfactants include, but are not limitedto fatty alcohols, cetyl alcohol, stearyl alcohol, and cetostearylalcohol. Fracturing fluid 108 may incorporate a surfactant or blend ofsurfactants in an amount between about 0.01 wt % and about 5 wt % oftotal fluid weight.

While the fracturing fluid of the present disclosure is described hereinas including the above-mentioned components, it should be understoodthat the fluid of the present disclosure may optionally include otherchemically different materials. In embodiments, the fluid may furthercomprise different stabilizing agents, surfactants, diverting agents,proppant, clay stabilizers, gel stabilizers, bactericides, or otheradditives.

The combined presence of crosslinkers and nanomaterials in fracturingfluid 108 enhances the fluid viscosity of the fracturing fluid attemperatures of about 270° F. to about 300° F. and above, with thefracturing fluid demonstrating a higher viscosity and a longer lifetimethan would be expected based on the properties of fracturing fluids withcrosslinkers or nanomaterials only. That is, the viscosity and viscositylifetime of fracturing fluid 108 with both crosslinkers andnanomaterials are greater than the sum of the effects of crosslinkersand nanomaterials taken separately. Moreover, this synergistic effectoffers significant, practical advantages, including the ability to usesalt water rather than fresh water for fracturing fluids, the ability toreduce polymer loading to achieve a desired viscosity, and the abilityto achieve better formation cleanup after the fracturing treatment.

The control trucks 112 can include mobile vehicles, immobileinstallations, and/or other suitable structures. The control trucks 112can control and/or monitor the injection treatment. For example, thecontrol trucks 112 can include communication links that allow thecontrol trucks 112 to communicate with tools, sensors, and/or otherdevices installed in the wellbore 103. The control trucks 112 canreceive data from, or otherwise communicate with, a computing system 124that monitors one or more aspects of the acid treatment.

In addition, the control trucks 112 can include communication links thatallow the control trucks 112 to communicate with the pump trucks 114and/or other systems. The control trucks 112 can include an injectioncontrol system that controls the flow of the fracturing fluid 108 intothe reservoir 106. For example, the control trucks 112 can monitorand/or control the concentration, density, volume, flow rate, flowpressure, location, proppant, and/or other properties of the fracturingfluid 108 injected into the reservoir 106. The reservoir 106 can includea fracture network with multiple fractures 116, as shown in FIG. 1

The features described can be implemented in digital electroniccircuitry, or in computer hardware, firmware, software, or incombinations of them. The apparatus can be implemented in a computerprogram product tangibly embodied in an information carrier, e.g., in amachine-readable storage device, for execution by a programmableprocessor; and method steps can be performed by a programmable processorexecuting a program of instructions to perform functions of thedescribed implementations by operating on input data and generatingoutput. The described features can be implemented advantageously in oneor more computer programs that are executable on a programmable systemincluding at least one programmable processor coupled to receive dataand instructions from, and to transmit data and instructions to, a datastorage system, at least one input device, and at least one outputdevice. A computer program is a set of instructions that can be used,directly or indirectly, in a computer to perform a certain activity orbring about a certain result. A computer program can be written in anyform of programming language, including compiled or interpretedlanguages, and it can be deployed in any form, including as astand-alone program or as a module, component, subroutine, or other unitsuitable for use in a computing environment.

Suitable processors for the execution of a program of instructionsinclude, by way of example, both general and special purposemicroprocessors, and the sole processor or one of multiple processors ofany kind of computer. Generally, a processor will receive instructionsand data from a read-only memory or a random access memory or both.Elements of a computer can include a processor for executinginstructions and one or more memories for storing instructions and data.Generally, a computer will also include, or be operatively coupled tocommunicate with, one or more mass storage devices for storing datafiles; such devices include magnetic disks, such as internal hard disksand removable disks; magneto-optical disks; and optical disks. Storagedevices suitable for tangibly embodying computer program instructionsand data include all forms of non-volatile memory, including by way ofexample semiconductor memory devices, such as EPROM, EEPROM, and flashmemory devices; magnetic disks such as internal hard disks and removabledisks; magneto-optical disks; and CD-ROM and DVD-ROM disks. Theprocessor and the memory can be supplemented by, or incorporated in,ASICs (application-specific integrated circuits).

To provide for interaction with a user, the features can be implementedon a computer having a display device such as a CRT (cathode ray tube)or LCD (liquid crystal display) monitor for displaying information tothe user and a keyboard and a pointing device such as a mouse or atrackball by which the user can provide input to the computer.

The features can be implemented in a computer system that includes aback-end component, such as a data server, or that includes a middlewarecomponent, such as an application server or an Internet server, or thatincludes a front-end component, such as a client computer having agraphical user interface or an Internet browser, or any combination ofthem. The components of the system can be connected by any form ormedium of digital data communication such as a communication network.Examples of communication networks include, e.g., a LAN, a WAN, and thecomputers and networks forming the Internet.

The computer system can include clients and servers. A client and serverare generally remote from each other and typically interact through anetwork, such as the described one. The relationship of client andserver arises by virtue of computer programs running on the respectivecomputers and having a client-server relationship to each other.

In addition, the logic flows depicted in the figures do not require theparticular order shown, or sequential order, to achieve desirableresults. In addition, other steps may be provided, or steps may beeliminated, from the described flows, and other components may be addedto, or removed from, the described systems. Accordingly, otherimplementations are within the scope of the following claims.

Examples

The following examples are put forth so as to provide those of ordinaryskill in the art with a complete disclosure and description of how thecompositions disclosed herein are made and evaluated, and are intendedto be purely exemplary and are not intended to be limiting in scope.Efforts have been made to ensure accuracy with respect to numbers (e.g.,amounts, temperature, etc.), but some errors and deviations should beaccounted for.

Examples 1-6 provide exemplary fracturing fluids prepared in untreatedseawater and including a crosslinker and metal oxide nanoparticles.Comparative examples include fracturing fluids prepared in untreatedseawater with a crosslinker or metal oxide nanoparticles, but not both.Fracturing fluids were prepared using a blender (e.g., a WARINGblender). The polymer was hydrated in the seawater first to form a basefluid. Additives (e.g., buffer and stabilizer) were added to the basefluid followed by the addition of nanomaterial and the crosslinker.FIGS. 2-7 show plots of viscosity (cP) at 40/s shear rate over time forthe fracturing fluids at the temperature shown by plots 200, 300, 400,500, 600, and 700, respectively. Viscosity of the fracturing fluids wasmeasured at a shear rate of 40 sec⁻¹ at selected temperatures with aFann 50-type High-Pressure, High-Temperature (HPHT) viscometer (e.g., aGrace M5600 HPHT Rheometer).

Untreated Saudi seawater (TDS of about 57,000 mg/L) was used to preparethe fracturing fluids in Examples 1-6. The ZrO₂ nanoparticle solution(20 wt %, 45-55 nm), TiO₂ nanoparticle solution (rutile, 15 wt %, 5-15nm), and CeO₂ nanoparticle solution (20 wt %, 30-50 nm) werecommercially available products, and used as received without furthertreatment. The Zr crosslinkers, the HPG slurry, and the sorbitolderivative are all commercially available.

Example 1

Comparative Fracturing Fluids 1A and 1B (CFF1A and CFF1B, respectively)and Fracturing Fluid 1 (FF1) were prepared as shown in Table 1. CFF1Awas prepared with seawater (TDS of about 57,000 mg/L), 60 ppt HPG slurry(i.e., containing 60 ppt of dried HPG), 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃. 5H₂O, 10 ppt sorbitol, and crosslinked with 5 gpt of the Zr crosslinker(type 1). Plot 200 in FIG. 2 shows the temperature (° F.) at whichviscosity measurements were made. Plot 202 shows the viscosity of CFF1Aat 270° F. The fluid viscosity stayed above 500 cP for about 44 minutes.CFF1B was prepared with seawater, 60 ppt HPG slurry, 2 ppt NaHCO₃, 10ppt Na₂S₂O₃. 5 H₂O, 10 ppt sorbitol, and 1 gpt of the ZrO₂ nanoparticlesolution. No Zr crosslinker was present in CFF1B. As shown in plot 204,the viscosity of CFF1B at 270° F. decreased rapidly and never reached500 cP. FF1 was prepared with seawater, 60 ppt HPG slurry, 2 ppt NaHCO₃,10 ppt Na₂S₂O₃. 5 H₂O, 10 ppt sorbitol, 1 gpt of the ZrO₂ nanoparticlesolution, and 5 gpt of the Zr crosslinker (type 1). As shown in plot206, the viscosity of FF1 at 270° F. stayed above 500 cP for about 95minutes. FF1 demonstrated a longer lifetime (e.g., length of time with aviscosity above 500 cP), and the viscosity of FF1 was higher than thatof CFF1A and CFF1B combined at elapsed times exceeding about 20 minutes,indicating that the Zr crosslinker and the ZrO₂ nanoparticles in FF1worked synergically to enhance the fluid viscosity of FF1.

TABLE 1 Example 1: Fracturing fluid with Zr crosslinker and ZrO₂nanoparticles. Component CFF1A CFF1B FF1 Seawater (TDS 57,000 mg/L) HPGslurry (ppt) 60 60 60 NaHCO₃ (ppt) 2 2 2 Na₂S₂O₃•5H₂O (ppt) 10 10 10Sorbitol (ppt) 10 10 10 Zr crosslinker (gpt) 5 5 ZrO₂ nanoparticlesolution 1 1 (gpt)

Example 2

Comparative Fracturing Fluids 2A and 2B (CFF2A and CFF2B, respectively)and Fracturing Fluid 2 (FF2) were prepared as shown in Table 2. CFF2Awas prepared with seawater (TDS of about 57,000 mg/L), 60 ppt HPGslurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃. 5 H₂O, 10 ppt sorbitol, andcrosslinked with 5 gpt of Zr crosslinker (type 1). Plot 300 in FIG. 3shows the temperature (° F.) at which viscosity measurements were made.As shown in plot 302, the fluid viscosity of CFF2A stayed above 500 cPfor about 44 minutes. CFF2B was prepared with seawater, 60 ppt HPGslurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃. 5 H₂O, 10 ppt sorbitol, and 1 gptof the TiO₂ nanoparticle solution. No Zr crosslinker was present inCFF2B. As shown in plot 304, the viscosity of CFF2B at 270° F. decreasedrapidly and never reached 500 cP. FF2 was prepared with seawater, 60 pptHPG slurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃. 5 H₂O, 10 ppt sorbitol, 1 gptof the TiO₂ nanoparticle solution, and 5 gpt of the Zr crosslinker (type1). As shown in plot 306, the viscosity of FF2 at 270° F. stayed above500 cP for about 78 minutes. FF2 demonstrated a longer lifetime (e.g.,length of time with a viscosity above 500 cP), and the viscosity of FF2was higher than that of CFF2A and CFF2B combined at elapsed timesexceeding about 20 minutes, indicating that the Zr crosslinker and thenano TiO₂ in FF2 worked synergically to enhance the fluid viscosity ofFF2.

TABLE 2 Example 2: Fracturing fluid with Zr crosslinker and TiO₂nanoparticles. Component CFF2A CFF2B FF2 Seawater (TDS 57,000 mg/L) HPGslurry (ppt) 60 60 60 NaHCO₃ (ppt) 2 2 2 Na₂S₂O₃•5H₂O (ppt) 10 10 10Sorbitol (ppt) 10 10 10 Zr crosslinker (gpt) 5 5 TiO₂ nanoparticlesolution 1 1 (gpt)

Example 3

Comparative Fracturing Fluids 3A and 3B (CFF3A and CFF3B, respectively)and Fracturing Fluid 3 (FF3) were prepared as shown in Table 3. CFF3Awas prepared with seawater, 60 ppt HPG slurry, 2 ppt NaHCO₃, 10 pptNa₂S₂O₃. 5 H₂O, 10 ppt sorbitol, and crosslinked with 5 gpt of the Zrcrosslinker (type 1). Plot 400 in FIG. 4 shows the temperature (° F.) atwhich viscosity measurements were made. As shown in plot 402, the fluidviscosity of CFF3A stayed above 500 cP for about 44 minutes. FF3 wasprepared with seawater, 60 ppt HPG slurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5 H₂O, 10 ppt sorbitol, 1 gpt of the CeO₂ nanoparticle solution, and 5gpt of the Zr crosslinker (type 1). As shown in plot 406, the viscosityof FF3 at 270° F. stayed above 500 cP for about 64 minutes. FF3demonstrated a longer lifetime (e.g., length of time with a viscosityabove 500 cP) than CFF3A, and the viscosity of FF3 was higher than thatof CFF3A at elapsed times exceeding about 20 minutes. CFF3B was preparedwith seawater, 60 ppt HPG slurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃, .5H₂O,and 10 ppt sorbitol; 1 gpt of the CeO₂ nanoparticle solution was thenadded. The Zr crosslinker was not used. The viscosity of the fluid (notshown) at 270° F. quickly dropped below 500 cP within minutes. Thissuggests that the Zr crosslinker and the CeO₂ nanoparticles workedsynergically to enhance the fluid viscosity.

TABLE 3 Example 3: Fracturing fluid with Zr crosslinker and CeO₂nanoparticles. Component CFF3A CFF3B FF3 Seawater (TDS 57,000 mg/L) HPGslurry (ppt) 60 60 60 NaHCO₃ (ppt) 2 2 2 Na₂S₂O₃•5H₂O (ppt) 10 10 10Sorbitol (ppt) 10 10 10 Zr crosslinker (gpt) 5 5 CeO₂ nanoparticlesolution 1 1 (gpt)

Example 4

Comparative Fracturing Fluid 4A (CFF4A) and Fracturing Fluid 4 (FF4)were prepared as shown in Table 4. CFF4A was prepared with seawater, 60ppt HPG slurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5H₂O, 10 ppt sorbitol, andcrosslinked with 5 gpt of the Zr crosslinker (type 1). Plot 500 in FIG.5 shows the temperature (° F.) at which viscosity measurements weremade. As shown in plot 502, the fluid viscosity of CFF4A stayed above500 cP for about 44 minutes. FF4 was prepared with seawater, 50 ppt HPGslurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5H₂O, 10 ppt sorbitol, 1 gpt of theZrO₂ nanoparticle solution, and 5 gpt of the Zr crosslinker (type 1). Asshown in plot 506, the viscosity of FF4 at 270° F. stayed above 500 cPfor about 59 minutes. Even with 50 ppt of the polymer loading, FF4showed a longer lifetime than CFF4A with 60 ppt of the polymer. Thus,the addition of 1 gpt of the ZrO₂ nanoparticle solution appears tocompensate for a lower polymer content without sacrificing the fluidperformance at high temperatures. Reduced polymer loading usuallytranslates into better formation cleanup after the fracturing treatment.

TABLE 4 Example 4: Fracturing fluid with Zr crosslinker and ZrO₂nanoparticles. Component CFF4A FF4 Seawater (TDS 57,000 mg/L) HPG slurry(ppt) 60 50 NaHCO₃ (ppt) 2 2 Na₂S₂O₃•5H₂O (ppt) 10 10 Sorbitol (ppt) 1010 Zr crosslinker (ppt) 5 5 ZrO₂ nanoparticle solution (gpt) 1

Example 5

Comparative Fracturing Fluids 5A and 5B (CFF5A and CFF5B, respectively)and Fracturing Fluid 5 (FF5) were prepared as shown in Table 5. CFF5Awas prepared with seawater, 54 ppt HPG slurry, 2 ppt NaHCO₃, 10 pptNa₂S₂O₃.5H₂O, 5 gpt of commercially available alkylated sorbitol, andcrosslinked with 2.8 gpt of Zr crosslinker (type 2, pH adjusted to about6.0). No nano solution was added to CFF5A. Plot 600 in FIG. 6 shows thetemperature (° F.) at which viscosity measurements were made. As shownin plot 602, the fluid viscosity of CFF5A at 285° F. stayed above 500 cPfor about 100 minutes. FF5 was prepared with seawater, 54 ppt HPGslurry, 2 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5H₂O, 5 gpt of the alkylatedsorbitol, 0.5 gpt of the ZrO₂ nanoparticle solution, and 2.8 gpt of theZr crosslinker (Type 2, pH adjusted to about 6.0). As shown in plot 606,the viscosity of FF5 at 285° F. stayed above 500 cP for about 134minutes. With the same polymer loading, FF5 showed longer lifetime thanCFF5A due to the addition of 0.5 gpt of the nano ZrO₂ solution. CFF5Bwas prepared with seawater, 54 ppt HPG slurry, 2 ppt NaHCO₃, 10 pptNa₂S₂O₃.5H₂O, and 5 gpt the alkylated sorbitol; 0.5 gpt of the ZrO₂nanoparticle solution was then added. The Zr crosslinker was not used.The viscosity of the fluid (not shown) at 285° F. quickly dropped below500 cP within minutes. This again suggests that the Zr crosslinker andthe nano ZrO₂ worked synergically to enhance the fluid viscosity.

TABLE 5 Example 5: Fracturing fluid with Zr crosslinker and ZrO₂nanoparticles. Component CFF5A CFF5B FF5 Seawater (TDS 57,000 mg/L) HPGslurry (ppt) 54 54 54 NaHCO₃ (ppt) 2 2 2 Na₂S₂O₃•5H₂O (ppt) 10 10 10alkylated sorbitol (gpt) 5 5 5 Zr crosslinker, type 2 (gpt) 2.8 2.8 ZrO₂nanoparticle solution 0.5 0.5 (gpt)

Example 6

Comparative Fracturing Fluids 6A and 6B (CFF6A and CFF6B, respectively)and Fracturing Fluid 6 (FF6) were prepared as shown in Table 6. CFF6Awas prepared with seawater, 60 ppt HPG slurry, 4 ppt NaHCO₃, 10 pptNa₂S₂O₃.5H₂O, 5 gpt commercially available alkylated sorbitol, andcrosslinked with 2.8 gpt of the Zr crosslinker (Type 2, pH adjusted toabout 6.0). No nanoparticle solution was added to CFF6A. Plot 700 inFIG. 7 shows the temperature (° F.) at which viscosity measurements weremade. As shown in plot 702, the fluid viscosity of CFF6A at 300° F.stayed above 500 cP for about 60 minutes. FF6 was prepared withseawater, 60 ppt HPG slurry, 4 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5H₂O, 5 gpt ofthe alkylated sorbitol, 1 gpt of the ZrO₂ nanoparticle solution, and 2.8gpt of the Zr crosslinker (Type 2, pH adjusted to about 6.0). As shownin plot 706, the viscosity of FF6 at 300° F. stayed above 500 cP forabout 78 minutes. With the same polymer loading, FF6 showed a longerlifetime than CFF6A due to the addition of 1 gpt of the ZrO₂nanoparticle solution. CFF6B was prepared with seawater, 60 ppt HPGslurry, 4 ppt NaHCO₃, 10 ppt Na₂S₂O₃.5H₂O, and 5 gpt of the alkylatedsorbitol; 1 gpt of the ZrO₂ nanoparticle solution was then added. The Zrcrosslinker was not used. The viscosity of the fluid (not shown) at 300°F. quickly dropped below 500 cP within minutes. This again suggests thatthe Zr crosslinker and the ZrO₂ nanoparticles worked synergically toenhance the fluid viscosity.

TABLE 6 Example 6: Fracturing fluid with Zr crosslinker and ZrO₂nanoparticles. Component CFF6A CFF6B FF6 Seawater (TDS 57,000 mg/L) HPGslurry (ppt) 60 60 60 NaHCO₃ (ppt) 4 4 4 Na₂S₂O₃•5H₂O (ppt) 10 10 10alkylated sorbitol (gpt) 5 5 5 Zr crosslinker, type 2 (gpt) 2.8 2.8 NanoTiO₂ solution (gpt) 1 1

By way of summary, Table 7 shows the length of time the variousfracturing fluids and comparative fracturing fluids (FFX, CFFXA, andCFFXB, where X corresponds to Example X) in Examples 1-6 maintained aviscosity above 500 cP at the elevated temperature disclosed withrespect to each example. As discussed above with respect to Examples1-6, these results demonstrate that presence of the nanoparticles has agreater than additive effect on the viscosity of the fracturing fluid atelevated temperatures. This synergistic effect is significant in thatavailable water sources with high levels of total dissolved solids canbe used to prepare fracturing fluids having a viscosity sufficient foruse at elevated temperatures of at least 270° F. (e.g., 270° F. to 300°F.). In addition, the synergistic effect allows for longer lifetimes forequivalent polymer loading, as well as longer lifetimes for lowerpolymer loadings.

TABLE 7 Length of time (min) viscosity exceeds 500 cP at elevatedtemperature. Example X CFFXA CFFXB FFX Example 1 44 0 95 Example 2 44 078 Example 3 44 0 64 Example 4 44 59 Example 5 100 134 Example 6 60 78

A number of implementations have been described. Nevertheless, it willbe understood that various modifications can be made without departingfrom the spirit and scope of the disclosure.

What is claimed is:
 1. A fracturing fluid comprising: a base fluidcomprising salt water; a polymer; a crosslinker; and a nanomaterial. 2.The fracturing fluid of claim 1, wherein the base fluid comprises totaldissolved solids of at least about 500 mg/L.
 3. The fracturing fluid ofclaim 1, wherein the salt water comprises seawater, produced water,brine, brackish water, or a combination thereof.
 4. The fracturing fluidof claim 3, wherein the seawater comprises untreated seawater.
 5. Thefracturing fluid of claim 1, wherein the crosslinker comprises a Zrcrosslinker, a Ti crosslinker, an Al crosslinker, a borate crosslinker,or a combination thereof.
 6. The fracturing fluid of claim 1, whereinthe fracturing fluid comprises from about 0.02% to about 2% by weight ofthe crosslinker.
 7. The fracturing fluid of claim 1, wherein thenanomaterial comprises ZrO₂ nanoparticles, TiO₂ nanoparticles, CeO₂nanoparticles, or a combination thereof.
 8. The fracturing fluid ofclaim 7, wherein the nanomaterial is stabilized with a polymer, asurfactant, or a combination thereof.
 9. The fracturing fluid of claim8, wherein the nanomaterial is stabilized with polyvinylpyrrolidone. 10.The fracturing fluid of claim 1, wherein the nanomaterial comprisescarbon nanotubes, carbon nanorods, nano graphene, nano graphene oxide,or a combination thereof.
 11. The fracturing fluid of claim 1, whereinthe nanomaterial comprises Zr nanoparticles, Ti nanoparticles, Cenanoparticles, or a combination thereof.
 12. The fracturing fluid ofclaim 1, wherein the nanomaterial comprises metal-organic polyhedracomprising Zr, Ti, Ce, or a combination thereof.
 13. The fracturingfluid of claim 1, wherein the fracturing fluid comprises about 0.0002%to about 2% by weight of the nanomaterial.
 14. The fracturing fluid ofclaim 1, wherein the polymer comprises guar, hydroxpropyl guar,carboxymethyl hydroxypropyl guar, or a combination thereof.
 15. Thefracturing fluid of claim 1, further comprising a bactericide.
 16. Thefracturing fluid of claim 1, further comprising a buffer, wherein thebuffer comprises bicarbonate, carbonate, acetate, or a combinationthereof.
 17. The fracturing fluid of claim 1, further comprising astabilizer, wherein the stabilizer comprises sodium thiosulfate,sorbitol, alkylated sorbitol, or a combination thereof.
 18. Thefracturing fluid of claim 1, further comprising a viscosity breaker,wherein the viscosity breaker comprises an oxidative breaker.
 19. Thefracturing fluid of claim 1, further comprising a surfactant.
 20. Thefracturing fluid of claim 1, further comprising a scale inhibitor.